Rotary Drill Bit

ABSTRACT

A rotary drill bit ( 10 ) is provided for drilling a hole in a subsurface formation. The bit body ( 12 ) includes a plurality of axially extending ribs ( 16   a, b, c  and  d ) and a flow channel between adjacent ribs. A plurality of cutting elements ( 19 ) are fixedly mounting on a respective one of the plurality of ribs. A plurality of flow nozzles ( 20   a, b, c  and  d ) direct fluid to a respective one of the plurality of cutting elements to clean and cool the cutting elements.

CROSS-REFERENCE TO RELATED APPLICATION

This application is a continuation-in-part of U.S. application Ser. No.12/509,202 filed on Jul. 24, 2009 which claims the priority of U.S.Provisional Application No. 61/083,741 filed on Jul. 25, 2008, thedisclosures of which are incorporated herein by reference for allpurposes.

FIELD OF THE INVENTION

The present invention relates to a rotary drill bit for drilling a holein a subsurface formation. More particularly, the invention relates to arotary drill bit which includes a plurality of cutting elements eachmounted on a respective one of a plurality of radially extending ribs,and a plurality of flow nozzles for directing fluid to a respective oneof the cutting elements.

BACKGROUND OF THE INVENTION

Rotary drill bits are commonly used to drill in a formation by cuttingthe soil or rock. Drilling mud is used to control subsurface pressures,lubricate the drill bit, stabilize the well bore, and carry the cuttingsto the surface. Mud is pumped from the surface through the hollow drillstring, exits through nozzles in the drill bit, and returns to thesurface through an annulus between the drill string and the interiorwall of the hole.

As the drill bit grinds rocks into drill cuttings, these cuttings becomeentrained in the mud flow and are carried to the surface. Prior toreturning the mud to the recirculating mud system, the solids areseparated from the mud. The first step in separating the cuttings fromthe mud commonly involves circulating the mixture of mud and cuttingsover shale shakers. The liquid mud passes through the shaker screens andis recirculated back to the mud tanks from which mud is withdrawn forpumping downhole. The vibratory action of the shakers moves the cuttingsdown the screen and off the end of the shakers, where they are collectedand stored in a tank or pit for further treatment or management. Oftentwo series of shale shakers are used. The first series (primary shakers)use coarse screens to remove only the larger cuttings. The second series(secondary shakers) use fine mesh screens to remove much smallerparticles.

Additional mechanical processing is often used in the recirculating mudsystem to further remove fine solids because these particles tend tointerfere with drilling performance. This separation equipment mayinclude one or more of three types: 1) hydrocyclone-type desilters anddesanders, 2) mud cleaners (hydrocyclone discharging on a fine screenedshaker), and 3) rotary bowl decanting centrifuges. The separated finesolids are typically combined with the larger drill cuttings removed bythe shale shakers.

Rate of penetration (ROP) of the drill bit is a major characteristic forwells, and often a critical cost issue for deep wells. Low ROP in theorder of 3-5 feet per hour is commonly the result of the highcompression strength of formations encountered at the greater depths,and the ineffectiveness of the cutting bit.

Subterranean drill bits can be used in many different applications, suchas oil and gas exploration, mining, construction, and geothermal. Thereare two main types of drill bits. A roller bit uses steel teeth ortungsten carbide inserts mounted with one, two, or three moving rollers.Tricone bits have three rollers with hardened inserts are used fordrilling hard formations at both shallower depths and deeper depths.However, at greater depths it is more difficult to recognize when atricone bit's bearings have failed, a situation that can occur withgreater frequency when greater weight is applied to the bit in a deepwell. This can lead to more frequent failures, lost cones, more frequenttrips (removal of all or some of the drill pipe from the hole), highercosts and lower overall rates of penetration.

Another type of cutter bit does not use any moving cutting mechanism.Fixed cutter bits frequently use polycrystalline diamond compact (PDC)cutters with synthetic polycrystalline diamonds bonded to atungsten-carbide stud or blade. PDC bits typically drill faster thantricone bits, particularly in softer formations, and PDC bit life hasincreased dramatically over the past 20 years. PDC bits neverthelesshave their own set of problems in hard formations. For example, “bitwhirl” is a problem that occurs when a PDC bit's center of rotationshifts away from its geometric center, producing a non-cylindrical hole.This can result from an unbalanced condition brought on byirregularities in the frictional forces between the rock and the bit.PDC bits are also susceptible to “stick slip” problems where the bithangs up momentarily, allowing its rotation to briefly stop and itstorque to increase, and then slips free to rotate at a high speed. WhilePDC cutters are good at shearing rock, they are susceptible to damagefrom sharp impacts that lead to problems in hard rocks, resulting inreduced bit life and lower overall rates of penetration. PDC bit designsfrequently include features that attempt to address these problems,namely, force balancing, spiraled or asymmetric cutter layouts, gaugerings, and hybrid cutter designs. Nevertheless, PDC bits frequently havesignificant shortcomings, particularly when drilling in extremeenvironments.

In a conventional drill bit, the mud flows from one or several nozzlesfor clearing and cooling the cutters. The mud jet is commonly directedstraight from the nozzle to the base of drilling bore (dome). Such flowof the mud causes numerous disadvantages. First, the jet entrains thedrill cuttings or solids, and brings them to the bottom of borehole.When drill cuttings go back up to the drill bit cutters, they erode thecutting elements, blades and bodies of PDC bits. Another disadvantage itthat heat is not appropriately transferred from the bit's cutters to themud, due to a relatively low speed of the mud flow through the debrisslots in the bit. This causes a large heat stress on the cutters thusreducing their rigidity, which in turn reduces the rate of penetrationand the operating hours for the drill bit.

U.S. Pat. No. 6,142,248 to Thigpen et al. discloses a method to reducenozzle erosion using a nozzle which supplies the mud in the laminar flowregime. An enhanced hydraulic design (Mudpick II) plays a key role inthe bit performance. The mud stream is directed first to clean thecutters and then it sweeps under a cutter at the point of formationcontact for efficient chip removal. The jet path from the nozzle expandsand meets the teeth on a roller cone, which commonly are not in thecontact with the formation. The jet dissipates and loses hydraulicenergy and does not provide the desired efficiency.

The disadvantages of the prior art are overcome by the presentinvention, and a new rotary drill bit and method of operating a drillbit are hereinafter disclosed.

SUMMARY OF THE INVENTION

In one embodiment, a rotary drill bit is provided for drilling a hole ina subsurface formation. The drill bit includes a bit body having aleading cutting face and outer peripheral edges. The bit body alsoincludes a plurality of radially extending ribs with a flow channelbetween adjacent ribs, and also includes a bit body flow path radiallyinward of the peripheral edges. A plurality of cutting elements are eachfixedly mounted on a respective one of the plurality of radiallyextending ribs. A plurality of flow nozzles are each in fluidcommunication with a bit body flow path to direct fluid to a respectiveone of the plurality of cutting elements to clean and cool the cuttingelement.

These and further features and advantages of the present invention willbecome apparent from the following detailed description, whereinreference is made to the figures in the accompanying drawings.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 illustrates a side view of one embodiment of a rotary bitaccording to the present invention.

FIG. 2 is a bottom view of the drill bit shown in FIG. 1.

FIG. 3 is a cross-sectional view taken along lines 3-3 in FIG. 2.

FIG. 4 is a detailed view of a portion of the bit shown in FIG. 3.

FIG. 5 is a side view of another embodiment of a drill bit.

FIG. 6 is a bottom view of the drill bit shown in FIG. 5.

FIG. 7 is a cross-sectional view taken along lines 7-7 in FIG. 6.

FIG. 8 is a detailed view of a portion of the bit shown in FIG. 7.

FIG. 9 is a side view of yet another embodiment of a drill bit.

FIG. 10 is a bottom view of the drill bit shown in FIG. 9.

FIG. 11 is a cross-sectional view taken along lines 11-11 in FIG. 10.

FIG. 12 is a detailed view of a portion of the bit shown in FIG. 11.

FIG. 13 is a cross-sectional view of another embodiment of a drill bit.

FIG. 14 is a detailed view of a portion of the bit shown in FIG. 13.

FIG. 15 is a side view of another embodiment of a drill bit.

FIG. 16 is a top view of the drill bit shown in FIG. 15.

FIG. 17 is a half-sectional view showing jets to individual cutters.

FIG. 18 is a detailed view of a portion of the drill bit shown in FIG.15, showing a jet to a single cutter.

DETAILED DESCRIPTION OF PREFERRED EMBODIMENTS

The present invention relates to improvements in drill bits which resultin improved rate of penetration (ROP), increased working hours, andreduced requirements for the strength of the cutters. The presentinvention provides a significantly improved hydraulic system whichmanages the fresh fluid flow to the teeth of the drill bit, therebyproviding more efficient removal of the cuttings. The operation of thisdownhole drill bit results in reduced thermal stresses at the cutter.One embodiment provides individual jet cooling of each tooth, improvedcleaning capability by supplying fresh fluid to the cutter, and reducederosion of the cutters. “Balling up” of the bit due to clogged flowchannels may desirably be reduced.

Referring now to FIG. 1, one embodiment of an improved rotary drill bit10 is illustrated, comprising a bit body 12 with upper threads 14 forinterconnection with a drill pipe or other tubular. Those skilled in theart will appreciate that box threads may be provided on the bit bodyrather than the pin threads. As shown in FIGS. 1 and 2, the drill bitincludes four circumferentially spaced blades or ribs 16 a, 16 b, 16 c,and 16 d. Each of these ribs supports a plurality of cutting elementseach fixed to a respective rib, such as cutting elements 18 shown inFIGS. 1 and 2. Each of the ribs or blades may have a generally curvedtriangular configuration, although other configurations may be providedfor the radially extending ribs. The bit 16 may be provided with gaugecutters 18, which may include PDC cutting elements, tungsten carbidecutters, or other metal alloy cutters.

Referring to FIGS. 1 and 2, the drill bit includes a plurality ofmanifolds 20 a, 20 b, 20 c, and 20 d, with each manifold comprising aplurality of discharge ports or jets 22. As explained subsequently, eachof the plurality of jets is beneficially directed toward a respectivecutter to provide increased cooling and cleaning for a cutting element.A jet may be a hole through a wall of the manifold and into the interiorof the manifold, or a desired size jet as an insert may be securedwithin a larger receiving hole in the manifold.

Referring now to FIG. 3, bit body 12 includes a central flow path 24therein for supplying fluid to the cutters. For this embodiment, amanifold 26 is attached to the bit body, and a flow line 28 transmitsdrilling fluid from the flow path 24 to the interior of the manifold 26.The manifold 26 in turn includes a flow chamber 30 therein, with aplurality of discharge ports or jets 22 discharging fluid from thechamber 30 to a respective cutting element 18. FIG. 4 illustrates thisfeature in greater detail, with jet 22 a being directed to cutter 18 a,jet 22 b being directed to cutter 18 b, and jet 22 x being directed tocutter 18 x.

Those skilled in the art should appreciate that the drill bit includes aplurality of cutters on each rib, and a jet is positioned for directingdrilling fluid to a respective one of the plurality of cutters on thatrib. In one example, a rib may contain seven cutters and the manifoldassociated with that rib may contain seven jets, with each jetcorresponding to a respective cutter. In other embodiments, however,more cutters than jets may be provided, so that one or more cutters maynot have a jet specifically directed to that cutter. In yet otherembodiments, a jet may be provided for each of the cutters on a rib, andanother jet may be provided for removing debris in a desired manner fromthe bit, and is not directed to a specific cutter. A plurality ofcutters are thus provided on each rib, and preferably four or morecutters are provided on each rib. Each of a plurality of cuttersprovided on a rib is provided with a respective jet, although additionalcutters may not have jets, and additional jets may not have acorresponding cutter. In most applications, however, at least 3 or 4cutters each supported on a rib will be supplied with fluid from a jetdirected to that cutter.

For the embodiment as shown in FIGS. 1-4, each of the jets 22 providedon a manifold 26 are spaced approximately a uniform distance from arespective jet. This provides substantially equal fluid velocity fromeach jet to a respective cutter. For the embodiment as shown in FIGS.5-8, a manifold is similarly provided for each rib, although in thisinstance each of the manifolds is spaced approximately equidistantbetween respective ribs.

FIG. 5 discloses a drill bit 10 which is similar to the drill bit shownin FIG. 1, except that the jets in the manifold 20 a are not spaced auniform distance from the cutters 18 fixed to the rib 16 a, and insteadthe spacing between a jet and a respective cutter increases as afunction of the radially outward distance of the cutters and the jetsfrom the centerline of the bit. As shown in FIG. 6, this allows themanifold to be spaced substantially equidistant between two ribs, whichmay provide for better flow of drilling fluids and solids into theannulus above the bit. The spacing between a jet and a respective cutterincreases as the cutter spacing from the centerline of the bitincreases, thereby increasing the washing area adjacent the cutters andimproving removal of debris.

The cross-section of the drill bit as shown in FIG. 7 is similar to thecross-section of FIG. 3, except that the spacing between a jet 22 and arespective cutter 18 increases as the jet and the spacing move radiallyfurther outward along the rib. FIG. 8 shows that a central jet path fromthe central axis of the discharge port for each jet to the primarycutting surface on the face of the bit. The correlation between a jetand the respective cutter does not appear to be as clear for theprevious embodiment since the cross-section is taken through themanifold, which is not parallel to the face of the cutters on a rib.Each jet central jet path 42 a, 42 b, 42 c, 42 d, 42 e, 42 f isillustrated in FIG. 8. Manifold 20 as shown in FIG. 8 includes an inletport 44 for directing fluids into the interior of the manifold cavity.The manifold itself as shown in FIGS. 1 and 2 may be secured in variousmanners to the bit body, e.g., with bolts and/or welding.

Another way to distinguish the jets in a drill bit of this inventionfrom the prior art relates to the high percentage of momentum of fluidfrom a specific jet which directly engages a primary cutting surface ofa respective cutter. According to this invention, a high percentage ofthe fluid momentum from a jet is directed to a respective cutter whichis highly beneficial to desired cooling and cleaning of a cuttingelement. The spacing between a jet and the respective cutter also ispreferably less than 12 times the mean diameter of the jet discharge,and in many cases is 10 times or less the mean diameter of the jetdischarge.

The drill bit 10 as shown in FIG. 9 is substantially similar to the FIG.5 embodiment, with each manifold 20 being spaced approximately equallybetween a pair of ribs 16. As seen more clearly in FIG. 11, the cavityin the manifold 20 is formed directly in the bit body 12, with a coverplate 52 enclosing the manifold cavity. The manifold includes aplurality of jets 22 each for directing fluid to a particular cutter 18,as previously discussed. The flow path 28 in the manifold body suppliesfluid from the central cavity 24 to the interior cavity in the manifold.FIG. 12 illustrates in further detail that the manifold includes aninterior wall 54 of the bit body 12 or the interior wall of an insertwhich is generally fixed to the bit body 12. The radially outer cover 56may also be part of insert or may be attached to the bit body by boltingor welding. Each of the jets 22 has fluid flow directed to a particularcutter, 18 as discussed for the prior embodiment. This built in designmay also be used for the manifold positioned as shown in FIG. 1.

FIG. 13 is a cross-sectional view of yet another embodiment of a drillbit body 12 with a central flow path 24 therein, and a plurality ofcutters 18 each affixed to a respective one of a plurality ofcircumferentially spaced ribs, as discussed above. This embodiment doesnot utilize a manifold, and instead a plurality of flow channels 28 eachconnecting the central flow path 24 to a respective jet, which in turndirects cooling fluid to a respective cutter 18. A plurality of cuttersare conventionally provided on each rib, and FIG. 13 depicts a flow line28 for each of the plurality of cutters, so that the six cutters asshown in FIG. 13 are each provided with a respective flow line 28emanating from the central flow path 24. FIG. 14 shows in greater detaileach of the flow paths 28 which has a discharge jet 62 at the dischargeend thereof for directing a jet to a respective one of the cutters. Theflow paths 28 may be provided in the bit body, or may be provided in aninsert separate from and fixed to the bit body, so that the dischargeports are spaced from the rib supporting a respective cutter. Highmanufacturing efficiency may be obtained by providing the dischargeports directly through the bit body.

FIG. 15 is a side view of another embodiment of a drill bit, and FIG. 16is a top view of the same drill bit. The drill bit of FIG. 15 is similarto the FIG. 13 drill bit, in that the bit body 12 has a central flowpath 24 which does not utilize a manifold, and instead of a plurality offlow channels 28 as shown in FIGS. 17 and 18 each connect the centralflow path 24 with a respective jet, which in turn is directed to arespective working cutter. Each discharge jet may thus be the exit portfrom a respective flow port through the bit body. The plurality ofcutters 18 are each affixed to a respective one of the plurality ofcircumferentially spaced ribs. The bit as shown in FIGS. 17 and 18includes three equally spaced primary ribs 72 each containing threeworking cutters, and three equally spaced secondary ribs 74 eachcontaining two working cutters. This drill bit has 9 jets each directedto one of the non-gauge cutters, and a total of 15 non-gauge cutters.

FIG. 17 shows one of the flow paths 28 with a jet 62 at the dischargeend thereof for directing the jet to a respective one of the threeprimary working cutters on a primary rib. FIG. 18 shows one jet directedto one of the two working cutters on a secondary rib 24. As with thepreviously described embodiments, the flow paths may be provided in abit body, or may be provided in an insert separate from and affixed tothe bit body.

In the event that the drill bit were to become partially plugged, thedrilling operator may lift the drill bit off the drilling surface andincrease fluid pressure in the annulus so that fluid backwashes into thedrill pipe, thereby flushing the flow paths and jets.

A method of drilling a hole in accordance with the present inventionincludes providing a bit body with a plurality of cutting elements eachfixed to a respective one of a plurality of radially extending ribs, asdiscussed above. The method includes directing fluid from the bit bodyflow path to a plurality of flow nozzles each for directing fluid to arespective one of a plurality of cutting elements to clean and cool thecutting elements. A manifold may be provided for receiving fluid flowfrom a bit body flow path and outputting fluid through the plurality offlow nozzles, or the bit body may include a plurality of flow lines eachextending from the bit body flow path to a respective one of theplurality of nozzles. Other features of the method of the invention willbecome apparent from the foregoing description.

The centerline of fluid flow from each nozzle is within 30° of a linepassing through a central axis of the nozzle discharge port and aprimary cutting surface on a respective cutting element, and in manyapplications this jet centerline is within 15° of a line passing throughthe nozzle central discharge port and a primary cutting surface,particularly when the jet discharge port is generally circular ratherthan being elliptical or slot-shaped.

As discussed above, the drill bit of the present invention includes aplurality of circumferentially spaced ribs, and each rib has fixedlymounted thereon a plurality of cutters. Larger diameter bitsconventionally have more cutters, and also have a larger central flowpath through the bit. According to the present invention, the meandiameter of the discharge port from each nozzle or jet is from about 3mm to about 20 mm, and for small and medium diameter bits is preferablyfrom 3 mm to about 10 mm. In many applications, the mean length of thedischarge port will be from 1 to 5 times the mean diameter of thedischarge port. The hole diameter may increase for jets spaced radiallyoutward from the bit centerline, particularly if the spacing between thejet and a respective cutter increases with this increased spacing. Eachnozzle conventionally may have a circular discharge opening, but inother configurations a non-circular opening could be provided. In eitherevent, the mean diameter of the opening is relatively small compared toprior art bits, since a discharge nozzle is preferably provided forprimarily cooling and cleaning one cutter, rather than a plurality ofcutters.

The sum of the cross-sectional flow areas for each of the jets in a bitmay approximate or be less than the flow area upstream from the jets.The use of multiple fluid jets each directed to a respective cutter onthe drill bit provides many benefits, such as improving the cleaning andscouring action, helping to remove the chip characteristics, and abetter environment for the cutter and formation contact, which reducesthe tooth wear, lubricates the teeth, provides uniform hydraulic balancefor the drill bit, and reduces the “whirl” effect by providing moreuniform cooling of the cutters and a cutting surface more uniformlyaffected by each of the plurality of cutters. The drill bit provides thefluid jet for cooling of an individual tooth, reducing the temperatureof the cutter tip, and improving rigidity characteristics. Theseimprovements increase the ROP, provide longer bit life, and allow fordrilling longer intervals. A significant advantage of this invention isthe reduction of erosion of the cutters as result of a substantial heatstress reduction and the reduction of the entrained drill cuttings inthe mud moving past cutters at the point of formation contact by a jet,each achieved by supplying fresh fluid to the cutters. The abovebenefits are particularly significant when most of the jets are directedto the “working” cutters, which is that group of cutters which primarilyremove the most formation rock and thus normally experience the mostwear. Such cutters typically may be identified as the radially outwardcutters which are on the shoulder of the bit. In most bit designs, theworking cutters are the cutters on the dome or face of the bit, ratherthan the side cutters along the gauge section of the bit. Preferablyjets are directed to many of the high wear cutters, and preferably atleast 30% of the cutters other than the gauge cutters. Another advantageprovided by this invention is the reduction of the heat stress on thecutters. In a conventional drill bit, mud first flows to the dome and onthe return goes through the junk slots, which has a relatively largearea. The mud velocity is thus small and consequently the coefficient ofheat transfer is small compared with the present invention. Anotheradvantage of this invention is that during the cutting process, each jetis helping to remove chips of rock by applying hydraulic energy directlyto the contact place between the primary cutting surface of a cutter andthe formation, thereby minimizing “redrilling” formation chips. Bettercleaning, cooling and lubrication of each individual cutter increasesthe rate of penetration and the operating hours for the drill bit.

A particular feature of the invention involves providing a large numberof jets relative to the number of cutters. Preferably the number of jetsin the bit is at least 30% of the non-gauge cutters. The embodiment asshown in FIG. 15 has 9 jets for the non-gauge cutters, while in otherapplications the bit may be provided with 12 or more jets for 24 or morenon-gauge cutters. The bit conventionally has these primary ribs, and insome applications, as shown in FIG. 17, has these secondary ribs eachcircumferentially spaced between two primary ribs. For most embodiments,two or more jets are directed to the non-gauge cutters on each of theprimary ribs.

Another feature of the invention is that each jet is preferably directedto the area on the cutter between the cutting edge of the cutter and thecenter of the cutter, thereby maximizing the effect of the jet for theefficient cutting action from a cutter. While a jet need not be directedto each working cutter, a jet directed to one working cutter willprovide conventional lubrication for adjacent cutters.

The tangential component of the flow path through the bit, and thus thetangential direction of the jet from that flow path, is believed tocontribute to the torque supplied to the bit. Bits are conventionallyrotated by applying torque to the drill string at the surface, and/orusing a downhole mud motor or a rotary steerable device. Much of theforce transmitted to the drill string is not applied to the bit, and islost due to frictional forces between the drill string and the wellboresurface. The longer the length of drill string being rotated, the morelikelihood that significant forces will be lost and not available torotate the drill bit. This is particularly important when drilling adeep well or a highly deviated well.

In accordance with the present invention, additional torque is createdby the fluid (mud) pressure and the tangential components of the jets.In some applications, this additional tangential force due to pressureof the hydraulic fluid and the jetting action of the bit may be asignificant portion of the torque actually applied to the bit.

Although specific embodiments of the invention have been describedherein in some detail, this has been done solely for the purposes ofexplaining the various aspects of the invention, and is not intended tolimit the scope of the invention as defined in the claims which follow.Those skilled in the art will understand that the embodiment shown anddescribed is exemplary, and various other substitutions, alterations andmodifications, including but not limited to those design alternativesspecifically discussed herein, may be made in the practice of theinvention without departing from its scope.

1. A rotary drill bit for drilling a hole in a subsurface formation,comprising: a bit body having a leading cutting face and outerperipheral edges, the bit body including a plurality of radiallyextending ribs with a flow channel between adjacent ribs, the bit bodyfurther including a bit body flow path radially inward of the peripheraledges; a plurality of cutting elements each fixedly mounted on arespective one of the plurality of radially extending ribs; and aplurality of flow nozzles each in fluid communication with the bit bodyflow path for directing fluid to a respective one of the plurality ofcutting elements to clean and cool the cutting element.
 2. A rotarydrill bit as defined in claim 1, wherein the plurality of cuttingelements each mounted on a respective blade include face cuttingelements for defining the leading cutting face substantiallyperpendicular to a bit centerline and side cutting elements adjacent theouter peripheral edges of the bit body.
 3. A rotary drill bit as definedin claim 1, further comprising: a manifold for receiving fluid flow fromthe bit body flow path and outputting flow through the plurality of flownozzles to the respective plurality of cutting elements mounted on arespective rib.
 4. A rotary drill bit as defined in claim 3, wherein themanifold is provided for each of the plurality of radially extendingribs.
 5. A rotary drill bit as defined in claim 3, wherein the manifoldpositions each of the plurality of nozzles a substantially uniformdistance from a respective cutting element.
 6. A rotary drill bit asdefined in claim 3, wherein the manifold positions each of the pluralityof nozzles an increasing distance from a respective cutting element as afunction of an increasing radial distance of a respective cuttingelement from a centerline of the bit.
 7. A rotary drill bit as definedin claim 3, wherein the manifold is attached to the bit body.
 8. Arotary drill bit as defined in claim 3, wherein a sidewall of themanifold is provided on an insert attached to the bit body.
 9. A rotarydrill bit as defined in claim 1, further comprising: a plurality of flowlines each extending from the bit body flow path to a respective one ofthe plurality of nozzles.
 10. A rotary drill bit as defined in claim 1,wherein a centerline of fluid flow from each nozzle is within 30° of aline passing through a central axis of the nozzle discharge port and aprimary cutting surface on a respective cutting element.
 11. A rotarydrill bit as defined in claim 1, wherein each nozzle has a mean diameterof from 3 mm to 20 mm.
 12. A rotary drill bit for drilling a hole in asubsurface formation, comprising: a bit body having a leading cuttingface and outer peripheral edges, the bit body including a plurality ofradially extending ribs with a flow channel between adjacent ribs, thebit body further including a bit body flow line within the bit body andradially inward of the peripheral edges; a plurality of cutting elementseach fixedly mounted on a respective one of the plurality of radiallyextending ribs; and a plurality of discharge jets each in fluidcommunication with a respective bit body flow line for directing fluidto a respective one of the plurality of cutting elements to clean andcool the cutting element.
 13. A rotary drill bit as defined in claim 12,wherein the plurality of cutting elements each mounted on a respectiveblade include face cutting elements for defining the leading cuttingface substantially perpendicular to a bit centerline and side cuttingelements adjacent the outer peripheral edges of the bit body.
 14. Arotary drill bit as defined in claim 12, wherein a centerline of fluidflow from each jet is within 30° of a line passing through a centralaxis of the jet discharge port and a primary cutting surface on arespective cutting element.
 15. A rotary drill bit as defined in claim12, wherein each jet directs fluid to a respective cutting element. 16.A rotary drill bit as defined in claim 12, wherein each nozzle has amean diameter of from 3 mm to 20 mm.
 17. A rotary drill bit as definedin claim 12, wherein flow through the plurality of jets creates atangential force to assist in rotating the drill bit.
 18. A method offorming a drill bit for drilling a hole in a subsurface formation,comprising: providing a bit body having a plurality of radiallyextending ribs with a flow channel between adjacent ribs, the bit bodyfurther including a bit body flow path radially inward of its peripheraledges; fixedly mounting a plurality of cutting elements on a respectiveone of the plurality of radially extending ribs; and providing aplurality of discharge jets each in fluid communication with the bitbody flow path for directing fluid to a respective one of the pluralityof cutting elements.
 19. A method as defined in claim 18, wherein flowthrough the plurality of jets creates a tangential force to assist inrotating the drill bit.
 20. A method as defined in claim 18, wherein acenterline of fluid flow from each nozzle is within 30° of a linepassing through a central axis of the nozzle discharge port and aprimary cutting surface on a respective cutting element.